Rotating stage collar

ABSTRACT

The disclosed embodiments include a rotating stage collar. The rotating stage collar includes an upper collar configured to couple to a first length of tubular, a lower collar configured to couple to a second length of tubular, and an inner sleeve disposed within the upper collar and the lower collar, wherein the upper collar and the lower collar are rotationally fixed to one another when the inner sleeve is in a first position within the upper collar and the lower collar, wherein the upper collar and the lower collar are rotationally independent of one another when the inner sleeve is in a second position within the upper collar and the lower collar, and wherein the second position is axially beneath the first position relative to a longitudinal axis of the rotating stage collar when the rotating stage collar is positioned within a wellbore.

FIELD OF DISCLOSURE

The present disclosure relates generally to the field of well drilling operations. More specifically, embodiments of the present disclosure relate to rotating stage collars for use with casing and cementing in a down-hole environment.

BACKGROUND

In conventional oil and gas operations, a well is typically drilled to a desired depth with a drill string, which includes drill pipe and a drilling bottom hole assembly (BHA). Once the desired depth is reached, the drill string is removed from the hole and casing is run into the vacant hole. In some conventional operations, the casing may be installed as part of the drilling process. A technique that involves running casing at the same time the well is being drilled may be referred to as “casing-while-drilling.”

Casing may be defined as pipe or tubular that is placed in a well to prevent the well from caving in, to contain fluids, and to assist with efficient extraction of product. When the casing is properly positioned within a hole or well, the casing is typically cemented in place by pumping cement through the casing and into an annulus formed between the casing and the hole (e.g., a wellbore or parent casing). As the cement is pumped through the casing and into the annulus, the casing may be rotated within the wellbore to help facilitate proper migration and settling of the casing within the annulus. Once a casing string has been positioned and cemented in place or installed, the process may be repeated via the now installed casing string. For example, the well may be drilled further by passing a drilling BHA through the installed casing string and drilling. Further, additional casing strings may be subsequently passed through the installed casing string (during or after drilling) for installation. Indeed, numerous levels of casing may be employed in a well, with each level having multiple stages. For example, once a first string of casing is in place, the well may be drilled further and another string of casing (an inner string of casing) with an outside diameter that is accommodated by the inside diameter of the previously installed casing may be run through the existing casing. Additional strings of casing may be added in this manner such that numerous concentric strings of casing are positioned in the well, and such that each inner string of casing extends deeper than the previously installed casing or parent casing string.

BRIEF DESCRIPTION

In a first embodiment, a system includes a rotating stage collar having an upper collar configured to couple to a first length of tubular, a lower collar configured to couple to a second length of tubular, and an inner sleeve disposed within the upper collar and the lower collar, wherein the upper collar and the lower collar are rotationally fixed to one another when the inner sleeve is in a first position within the upper collar and the lower collar, wherein the upper collar and the lower collar are rotationally independent of one another when the inner sleeve is in a second position within the upper collar and the lower collar, and wherein the second position is axially beneath the first position relative to a longitudinal axis of the rotating stage collar when the rotating stage collar is positioned within a wellbore.

In a second embodiment, a system includes a first tubular configured to be secured within a wellbore, a second tubular configured to be secured within the wellbore, and a rotating stage collar. The rotating stage collar includes an upper collar coupled to the first tubular, a lower collar coupled to the second tubular, a load nut disposed radially about the upper collar and threaded to the lower collar, and an inner sleeve disposed within the upper collar and the lower collar, wherein the upper collar and the lower collar are rotationally fixed relative to one another when the inner sleeve is in a first position within the upper collar and the lower collar, and the upper collar and lower collar are rotationally independent of one another when the inner sleeve is in a second position within the upper collar and the lower collar, and wherein the second position is axially beneath the first position relative to a longitudinal axis of the rotating stage collar when the rotating stage collar is positioned within the wellbore.

In a third embodiment, a method includes coupling a lower collar of a rotating stage collar to a first stage of casing, coupling an upper collar of the rotating stage collar to a second stage of casing, positioning the first stage of casing, the rotating stage collar, and the second stage of casing into a wellbore, rotating the first stage of casing, the rotating stage collar, and the second stage of casing while completing a first stage cementing process, displacing an inner sleeve of the rotating stage collar axially downward within the upper collar and the lower collar to rotationally disengage the upper collar from the lower collar, and rotating the second stage of casing without rotating the first stage of casing while completing a second stage cementing process.

DRAWINGS

These and other features, aspects, and advantages of the present invention will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:

FIG. 1 is a schematic representation of a well being drilled, in accordance with an embodiment of the present disclosure;

FIG. 2 is a schematic of a well with multiple stages of casing run into a wellbore, in accordance with an embodiment of the present disclosure;

FIG. 3 is a side view of a rotating stage collar coupling two stages of casing, in accordance with an embodiment of the present disclosure;

FIG. 4 is a cross-sectional side view, taken along line 4-4 of FIG. 3, of the rotating stage collar, illustrating the rotating stage collar in a locked configuration, in accordance with an embodiment of the present disclosure;

FIG. 5 is a cross-sectional side view of the rotating stage collar, illustrating a plug landed within the rotating stage collar and the rotating stage collar in a partially unlocked configuration, in accordance with an embodiment of the present disclosure; and

FIG. 6 is a cross-sectional side view of the rotating stage collar, illustrating a plug landed within the rotating stage collar and the rotating stage collar in a fully unlocked configuration, in accordance with an embodiment of the present disclosure.

DETAILED DESCRIPTION

The present disclosure relates generally to a rotating stage collar for coupling two adjacent stages of tubular (e.g., casing) run into a wellbore. During a mineral extraction process, a wellbore may be drilled and lined with casing (e.g., pipe) to prevent the wellbore from caving in, to contain fluids produced from a well, and to assist with efficient extraction of minerals. Once the casing is run into the wellbore, the casing may be cemented in place via cement pumped through the casing and into the annulus between the casing and the wellbore. In certain applications, it is desirable to rotate the casing within the wellbore as cement is pumped through the casing into the annulus. Indeed, rotating the casing during the cementing process may improve the displacement and flow of the cement into the annulus. Rotating casing during cementing also helps reduce gas migration, channeling, micro-annulus formation, zonal isolation, and other issues associated with cementing.

Casing cementing processes may be completed in stages. More specifically, a casing string having multiple stages (e.g., sections of the casing string) may be run into a wellbore, and cement may be pumped into the annulus surrounding the one casing string stage before the cement of a subsequent casing string stage is pumped into place. As described in detail below, adjacent stages or sections of the casing string may be coupled to one another via a rotating stage collar to selectively enable relative rotation between adjacent casing string stages. For example, a casing string having first, second, and third stages may be run into the wellbore. The first stage may be a lower stage, the second stage may be an intermediate stage, and the third stage may be an upper stage. After the casing string is run into the wellbore, cement may be pumped through the casing string to fill the annulus surrounding the first (e.g., lower) stage of casing while rotating the first, second, and third stages to improve the cementing process. After the first (e.g., lower) stage of casing is cemented, cement may be pumped into through the casing string to fill the annulus surrounding the second (e.g., intermediate) stage of casing while rotating the second (e.g., intermediate) and third (e.g., upper) stages, but not the first (e.g., lower) stage. To enable this functionality, the first and second stages may be coupled to one another with a first rotating stage collar. When the casing string is initially run into the wellbore, the rotating stage collar may be in a locked configuration, which keeps the first and second stages rotationally fixed relative to one another. After the first stage of the casing string is cemented in place, the rotating stage collar may be actuated or triggered from the locked configuration to an unlocked configuration (e.g., without lifting the casing string at the surface). In the unlocked configuration, the first and second stages of the casing string are rotationally independent from one another. As a result, the second (and third) stages may be rotated as cement is pumped into the annulus surrounding the second stage without rotating the first stage of casing. In this manner, the cement surrounding the first stage may be undisturbed after the first stage cementing process is complete, while enabling rotation of the second and third casing string stages during completion of the second stage cementing process.

After the second stage cementing process is complete, a second rotating stage collar coupling the second (e.g., intermediate) stage and the third (e.g., upper) stage may be triggered or actuated from a locked to unlocked configuration, as similarly described above. Thereafter, the third stage of the casing string may be cemented in place while rotating the third stage of the casing string without rotating the recently-cemented second stage of the casing string. Details of the rotating stage collar are described below. Furthermore, while the present disclosure is described in the context of a casing stage cementing process, the disclosed rotating stage collars may be used with other processes, including plug cementing, squeeze cementing, liner cementing, reverse cementing, primary cementing, remedial cementing, and so forth.

Turning now to the drawings, FIG. 1 is a schematic representation of a well 10 that is being drilled, in accordance with present embodiments. In the illustrated embodiment, the well 10 includes a derrick 12, wellhead equipment 14, and several levels of casing 16 (e.g., pipe). For example, the well 10 includes a conductor casing 18 (e.g., first level of casing 16), a surface casing 20 (e.g., second level of casing 16), and an intermediate casing 22 (e.g., third level of casing 16). In certain embodiments, the casing 16 may include 42 foot segments of oilfield pipe having a suitable diameter (e.g., 13⅜ inches) that are joined as the casing 16 is lowered into a wellbore 24 of the well 10. As will be appreciated, in other embodiments, the length and/or diameter of segments of the casing 16 may be other lengths and/or diameters. The casing 16 is configured to isolate and/or protect the wellbore 24 from the surrounding subterranean environment. For example, the casing 16 may isolate the interior of the wellbore 24 from fresh water, salt water, or other minerals surrounding the wellbore 24.

The casing 16 may be lowered into the wellbore 24 with a running tool. As shown, once each level of casing 16 is lowered into the wellbore 24 of the well, the casing 16 is secured or cemented in place with cement 26. As described in detail below, the cement 26 may be pumped into the wellbore 24 after each level of casing 16 is landed in place within the wellbore 24. That is, each level of casing 16 may be individually lowered within the wellbore 24 and supported by a casing hanger. Thereafter, the cement 26 may be pumped through the casing 16 and into the wellbore 24, where the cement 26 may set and secure the casing 16 in place, as shown. As mentioned above, each level of casing 16 may include multiple stages of casing 16. In the manner described below, adjacent stages of casing 16 may be coupled to one another via rotating stage collars that enable selective relative rotation of the stages of casing 16. That is, the rotating stage collars enable adjacent stages of casing 16 to be rotationally fixed to one another and subsequently rotationally independent of one another. In the manner described below, the rotating stage collars improve the casing cementing process.

FIG. 2 is a schematic of the well 10 with multiple stages 50 of casing 16 run into the wellbore 24. For example, the casing 16 shown in FIG. 2 may be the intermediate casing 22 shown in FIG. 1 prior to cementing of the casing 16 within the wellbore 24. However, in other embodiments, the casing 16 may be any other casing 16 string run into the wellbore 24. In the illustrated embodiment, the casing 16 includes a first stage 52 (e.g., a lower stage), a second stage 54 (e.g., an intermediate stage), and a third stage 56 (e.g., an upper stage). Each stage 50 of casing 16 may include one or more segments of oilfield pipe that are joined together. The first and second stages 52 and 54 are coupled to one another via a first rotating stage collar 58, and the second and third stages 54 and 56 are coupled to one another via a second rotating stage collar 60.

The first and second rotating stages collars 58 and 60 enable selective relative rotation of the stages of casing 16 that the collars 58 and 60 couple to one another. Specifically, the first rotating stage collar 58 enables selective relative rotation of the second stage 54 and the first stage 52, and the second rotating stage collar 60 enables selective rotation of the third stage 56 and the second stage 54. This functionality is useful during a casing cementing process, because an already-cemented stage of casing 16 may be undisturbed while another stage of casing 16 is subsequently cemented. For example, in the illustrated embodiment, the first, second, and third stages of casing 52, 54, and 56 may be initially run into the wellbore 24. At this time, the first and second rotating stage collars 58 and 60 may both be in a locked configuration. Thus, the first and second stages 52 and 54 may be rotationally fixed relative to one another, and the second and third stages 54 and 56 maybe rotationally fixed relative to one another.

Once the first, second, and third stages of casing 52, 54, and 56 are run into the wellbore 24, the cementing process may begin. Specifically, cement 24 may be pumped down through the casing 16 and into an annulus 62 between the casing 16 and the wellbore 24, as indicated by arrows 64. To cement the first stage 52 of casing 16, cement 24 may be pumped into a first portion 66 of the annulus 62 surrounding the first stage 52 of the casing 16 (e.g., below line 68). While the cement 24 is pumped into the first portion 66 of the annulus 62, the entire casing 16 string (e.g., first, second, and third stages 52, 54, and 56) may be rotated by the wellhead equipment 14, because the first and second rotating stage collars 58 and 60 are both in the locked configuration. As discussed above, rotation of the casing 16 during cementing facilitates and improves the cementing process.

After the first portion 66 of the annulus 62 is filled with cement 24, rotation of the casing 16 may be stopped, and the cement 24 may be allowed to set. While the cement 24 in the first portion 66 of the annulus 62 sets, the first rotating stage collar 58 may be triggered or actuated into an unlocked configuration. This actuation is described in further detail below with reference to FIGS. 4-6. After the first rotating stage collar 58 is actuated, the first and second stages 52 and 54 of casing 16 may rotate independently of one another. More particularly, the second stage 54 of casing 16 may be rotated by the wellhead equipment 14 during a subsequent cementing process without rotating the first stage 52 of casing 16, which is already cemented. As a result, the settling and curing of the cement 24 in the first portion 66 of the annulus 62 may be undisturbed. Additionally, as described below, the first rotating stage collar 58 may be triggered or actuated into an unlocked configuration without lifting the casing 16 within the wellbore 24, thereby further avoiding disturbance in the first stage 52 and the cement 24 of the first portion 66.

As described in detail below, actuation of the first rotating stage collar 58 may also open cement ports of the first rotating stage collar 58 to enable cementing of the second stage 54 of casing 16. As a result, cement 24 may be pumped into a second portion 70 of the annulus 62 surrounding the second stage 54 of the casing 16 (e.g., below line 72), as indicated by arrows 74. While the cement 24 is pumped into the second portion 70 of the annulus 62, the second and third stages 54 and 56 of casing 16 may be rotated by the wellhead equipment 14, because the second rotating stage collar 60 remains in the locked configuration. However, the first stage 52 of casing 16 is not rotated, because the first rotating stage collar 58 was previously actuated from the locked to unlocked configuration, which enables relative rotation between the second stage 54 and first stage 52.

After the second portion 70 of the annulus 62 is filled with cement 24, rotation of the casing 16 may be stopped, and the cement 24 surrounding the second stage 54 may be allowed to set. While the cement 24 in the second portion 70 of the annulus 62 sets, the second rotating stage collar 60 may be triggered or actuated to an unlocked configuration, as described below. After the second rotating stage collar 60 is actuated, the second and third stages 54 and 56 of casing 16 may rotate independently of one another. More particularly, the third stage 56 of casing 16 may be rotated by the wellhead equipment 14 during a subsequent cementing process without rotating the second stage 54 of casing 16, which is already cemented. As a result, the settling and curing of the cement 24 in the second portion 70 of the annulus 62 may be undisturbed. Additionally, as described below, the second rotating stage collar 60 may be triggered or actuated into an unlocked configuration without lifting the casing 16 within the wellbore 24, thereby further avoiding disturbance in the second stage 54 and the cement 24 of the second portion 70.

As similarly mentioned above, actuation of the second rotating stage collar 60 may open cement ports of the second rotating stage collar 60 to enable cementing of the third stage 56 of casing 16. Thus, cement 24 may be pumped into a third portion 76 of the annulus 62 surrounding the third stage 56 of the casing 16, as indicated by arrows 78. While the cement 24 is pumped into the third portion 76 of the annulus 62, the third stage 56 of casing 16 may be rotated by the wellhead equipment 14, without rotating the second stage 54 of casing 16, because the second rotating stage collar 60 was previously actuated from the locked to unlocked configuration.

FIG. 3 is a side view of an embodiment of the first rotating stage collar 58 described above with reference to FIG. 2. It should be noted that the second rotating stage collar 60 may have a similar configuration with similar components. In the illustrated embodiment, the first rotating stage collar 58 includes an upper collar 100 (e.g., annular collar) and a lower collar 102 (e.g., annular collar). The upper collar 100 is coupled to the second stage 54 of casing 16, while the lower collar 102 is coupled to the first stage 52 of casing 16. For example, the upper collar 100 and lower collar 102 may be coupled to the first and second stages 52 and 54, respectively, via a threaded connection, bolted connection, or other suitable mechanical connection.

The upper and lower collars 100 and 102 are coupled to one another with a load nut 104. In particular, the load nut 104 extends over and radially about the upper collar 100, and the load nut 104 threads onto the lower collar 102. As described in further detail below, the load nut 104 axially captures a load shoulder of the upper collar 100 with the lower collar 102, which enables the full weight of the first stage 52 and lower collar 102 to hang off from the upper collar (100) while the casing 16 is run into the well.

The first rotating stage collar 58 also includes shear screws 106 extending radially inward from an outer surface 108 of the upper collar 100. As described in detail below, the shear screws 106 extend through the upper collar 100 and into an inner sleeve of the rotating stage collar 58 to hold the inner sleeve in place prior to actuation or the rotating stage collar 58. As mentioned above, the rotating stage collar 58 further includes cement ports 110. The cement ports 110 extend from the outer surface 108 of the upper collar 100 to an inner circumferential surface of the upper collar 100. However, as described below, when the first rotating stage collar 58 is initially run into the wellbore 24, the cement ports 110 are blocked or occluded by the inner sleeve of the rotating stage collar 58. After the first rotating stage collar 58 is actuated, the inner sleeve may be axially displaced downward, and the cement ports 110 may be opened or exposed to enable cement 24 flow from within the rotating stage collar 58, through the cement ports 110, and into the annulus 62.

FIG. 4 is a cross-sectional side view, taken within line 4-4 of FIG. 3, of the first rotating stage collar 58. As described above, the rotating stage collar 58 includes the upper collar 100 and the lower collar 102, which are coupled to one another via the load nut 104. When the load nut 104 is threaded onto the lower collar 102, an upper shoulder 120 of the load nut 104 axially captures a load shoulder 122 of the upper collar 100 with an axial end face 124 of the lower collar 102. The load shoulder 122 of the upper collar 100 helps transfer weight from the first stage 52 of casing 16 to the upper collar 102 and the second stage 54 of casing 16. However, a majority of the weight of the casing 16 may still be supported by the wellhead equipment 14. To further enable support of the second stage 52 casing 16 load, the first rotating stage collar 58 includes thrust bearings 126 (e.g., bronze thrust bearings). Specifically, a first thrust bearing 128 is disposed between the axial end face 124 of the lower collar 102 and the load shoulder 122, and a second thrust bearing 130 is disposed between the load shoulder 122 and the upper shoulder 120 of the load nut 104. As will be appreciated, the thrust bearings 126 enable load transfer from the upper collar 100 to the lower collar 102 while also facilitating and enabling relative rotation between the upper collar 100 and the lower collar 102.

As mentioned above, the first rotating stage collar 58 also includes an inner sleeve 132 disposed within the upper and lower collars 100 and 102. When the rotating stage collar 58 is initially coupled to the first and second stages 52 and 54 of casing 16 and run into the wellbore 24, the inner sleeve 132 is held in place within the upper and lower collars 100 and 102 by the shear screws 106. For example, the rotating stage collar 58 may include 4, 5, 6, 7, 8, 9, 10, or more shear screws configured to hold the inner sleeve 132 in place within the upper and lower collars 100 and 102. When the inner sleeve 132 is held in place in the configuration shown in FIG. 3, the inner sleeve 132 occludes or blocks the cement ports 110 of the upper collar 100. Thus, cement 24 flowing through the casing 16 string, and thus through an inner passage 134 of the rotating stage collar 58, is blocked from flowing through the cement ports 110. In certain embodiments, the inner sleeve 132 may be formed from aluminum or other relatively soft metal to enable drilling-out of the inner sleeve 132 after the casing cementing process is completed.

Furthermore, when the inner sleeve 132 is held in place in the configuration shown in FIG. 3, the rotating stage collar 58 is in a locked configuration. That is, the upper collar 100 and lower collar 102 are rotationally fixed relative to one another, thereby blocking relative rotation of the first and second stages 52 and 54 of casing 16. Relative rotation of the upper and lower collars 100 and 102 is blocked via locking protrusions 136 or locking “dogs” spaced circumferentially about the inner sleeve 132. In the configuration shown in FIG. 4, the dogs 136 of the inner sleeve 132 extend through guide slots 137 of the upper collar 100 and into locking slots 138 formed in the lower collar 102. In other words, the dogs 136 are disposed radially within the locking slots 138 of the lower collar 102 (e.g., relative to a longitudinal axis 143 of the rotating stage collar 58), and thus rotation of the inner sleeve 132 and upper collar 100 (which are coupled to one another via the shear pins 120) relative to the lower collar 102 is blocked.

As shown in FIG. 4, the locking slots 138 are formed in an upper portion 140 of the lower collar 102. However, the locking slots 138 are not formed in a lower portion 142, which is axially beneath the upper portion 140 (e.g., relative to the longitudinal axis 143 of the rotating stage collar 58), of the lower collar 102. Instead, the lower portion 142 includes a cavity or annular groove 144 extending circumferentially about the lower portion 142 of the lower collar 102. When the dogs 136 are disposed within the cavity 144 of the lower portion 142, circumferential movement of the dogs 136, the inner sleeve 132, and the upper collar 100 is unrestricted. Therefore, to actuate the rotating stage collar 58 from a locked to unlocked configuration, the inner sleeve 132 of the rotating stage collar 58 is displaced axially downward, as indicated by arrow 146.

Axially displacement of the inner sleeve 132 is achieved via launching of a plug down the casing 16 string and into the first rotating stage collar 58. After the plug is launched, the plug will travel down the casing 16 string and will land against a plug seat 148 of the inner sleeve 132. As described below, the plug enables shearing of the shear screws 106 and downward axial displacement of the inner sleeve 132 within the upper and lower collars 100 and 102. In the illustrated embodiment, the inner sleeve 132 of the first rotating stage collar 58 has an inner diameter 150, which may generally or approximately correspond with an outer diameter of the plug. More specifically, the outer diameter of the plug may be slightly larger than the inner diameter 150 of the seat 148 to enable landing of the plug against the seat 148.

It will be appreciated that the inner diameter 150 of the inner sleeve 132 of the first rotating stage collar 58 may be smaller than an inner diameter of the inner sleeve of the second rotating stage collar 60. The diameter of the inner sleeve of the second rotating stage collar 60 may be larger to enable passage of the plug that is launched to land against the plug seat 148 of the first rotating stage collar 58. As a result, actuation of the second rotating stage collar 60 may be achieved with another plug having a larger diameter corresponding to the larger diameter of the inner sleeve of the second rotating stage collar 60. Indeed, each additional rotating stage collar that is used along the casing 16 string may include an inner sleeve having a plug seat with a larger inner diameter than the plug seat inner diameter of the next successive rotating stage collar located further downhole along the casing 16 string. Similarly, for each additional rotating stage collar used along the casing 16 string, a larger diameter plug will be used to land against the respective plug seat of the rotating stage collar to enable actuation of the rotating stage collar.

FIG. 5 is a cross-sectional side view of the first rotating stage collar 58, illustrating a plug 200 landed against the plug seat 148 of the inner sleeve 132. As discussed above, the plug 200 is launched down the casing 16 string from the wellhead equipment 14 to actuate the first rotating stage collar 58 from the locked configuration shown in FIG. 4 into an unlocked configuration. That is, the plug 200 is launched down the casing 16 to the first rotating stage collar 58 when relative rotation between the first stage 52 of casing 16 and the second stage 54 of casing 16 is desired (e.g., during cementing of the second stage 54 of casing 16 after the first stage 52 of casing is cemented). It should be noted that the first rotating stage collar 58 is actuated from the locked configuration into the unlocked configuration without lifting the casing 16 string (e.g., with the wellhead equipment 14). As a result, the first stage 52 of casing 16 and the cement 24 surrounding the first stage 52 of casing 16 may be undisturbed when the first rotating stage collar 58 is actuated for rotation of the second stage 54 of casing 16.

As mentioned above, the plug 200 is landed against the plug seat 148 of the inner sleeve 132. In the illustrated embodiment, the plug 200 also includes a central passage 202. To launch the plug 200 from the wellhead equipment 14, a ball 204 may be used to block the central passage 202, build up pressure behind and above the plug 200, and launch the plug 200 to the first rotating stage collar 58. However, in other embodiments, the plug 200 may not include the central passage 202, and thus the ball 204 may not be used. In certain embodiments, the plug 200 may be a rubber or other elastomeric material that may deform to create a seal with the inner sleeve 132 to block cement 24 from passing the plug 200 within the inner sleeve 132.

After the plug 200 and ball 204 are landed within the first rotating stage collar 58, cement 24 may be pumped down the casing 16, and pressure of the cement 24 may build up above the plug 200 and the ball 204. Eventually, the pressure will overcome the yield strength of the shear pins 106, causing the shear pins 106 to shear and the inner sleeve 132 to be displaced axially downward, as indicated by arrow 206. As the inner sleeve 132 travels axially downward, the dogs 136 of the inner sleeve 132 move along the guide slots 137 of the upper sleeve 100 and from the upper portion 140 of the lower collar 102 to the lower portion 142 of the lower collar 102. As discussed above, when the dogs 136 are disposed in the upper portion 140, rotation of the inner sleeve 132 and the upper collar 100 coupled to the inner sleeve 132 via the shear pins 106 is blocked via the locking slots 138 formed in the upper portion 140. However, when the dogs 136 of the inner sleeve 132 are moved axially downward to the lower portion 142 of the inner sleeve 132, the dogs 136 are disposed within the cavity 144 of the lower portion 142 and are free to rotate. Thus, the inner sleeve 132 and the upper collar 100 (which are rotationally coupled to one another via the dogs 136 extending through the guide slots 137 of the upper collar 100) are free to rotate relative to the lower collar 102. In other words, the second stage 54 of casing 16 coupled to the upper collar 100 may be freely rotated with the wellhead equipment 14 without rotating the lower collar 102 coupled to the first stage 52 of casing 16.

It should be noted that the first rotating stage collar 58 shown in FIG. 5 is not in the fully unlocked configuration. More specifically, the dogs 136 of the inner sleeve 132 are not fully landed against a lower shoulder 208 of the lower portion 142 of the lower collar 102. Additionally, in the illustrated embodiment, the cement ports 110 of the upper collar 100 are still occluded or blocked by the inner sleeve 132. Indeed, the size (e.g., length) of the inner sleeve 132 and/or the location of the cement ports 110 along the upper collar 100 is selected such that the cement ports 110 are occluded by the inner sleeve 132 until the dogs 136 of the inner sleeve 132 are fully landed against the lower shoulder 208. In this manner, cement 24 pressure above the plug 200 and the ball 204 may be contained (e.g., and not flow out of the cement ports 110) until the rotating stage collar 58 is in the fully unlocked configuration. Once the dogs 136 are landed against the lower shoulder 208, the inner sleeve 132 is axially beneath the cement ports 110 and no longer blocks the cement ports 110, and cement 24 may freely flow out of the rotating stage collar 58 through the cement ports 100. For example, FIG. 6 is a cross-sectional side view of the first rotating stage collar 58, illustrating the dogs 136 of the inner sleeve 132 landed against the lower shoulder 208 of the lower collar 102. As indicated by arrows 220, cement 24 may flow through the cement ports 110 into the annulus 62 between the casing 16 string and the wellbore 24.

In certain embodiments, the first rotating stage collar 58 may include other components. For example, as shown in FIG. 6, the rotating stage collar 58 may include one or more seals 240 (e.g., annular seals, elastomeric seals, etc.) disposed between the upper collar 100 and lower collar 102 and/or between the inner sleeve 132 and the upper collar 100. The seals 240 may block bearing surfaces 242 between the upper collar 100 and lower collar 102 and/or between the inner sleeve 132 and the upper collar 100 from becoming contaminated. In certain embodiments, the bearing surfaces 242 between the upper collar 100 and lower collar 102 and/or between the inner sleeve 132 and the upper collar 100 may be lubricated (e.g., with grease or oil) when the rotating stage collar 58 is assembled to facilitate relative rotation between the upper collar 100, lower collar 102, and/or inner sleeve 132 when the rotating stage collar 58 is in the unlocked configuration shown in FIG. 6.

As describe above, the present disclosure relates generally to the rotating stage collar 58 for coupling two adjacent stages of casing 16 (e.g., first and second stages 52 and 54) run into the wellbore 24. Once the casing 16 is run into the wellbore 24, the casing may be cemented in place via cement 24 pumped through the casing 16 and into the annulus 62 between the casing 16 and the wellbore 24. The adjacent stages (e.g., first and second stages 52 and 54) of the casing 16 string may be coupled to one another via the rotating stage collar 58 to selectively enable relative rotation between adjacent casing string stages. For example, cement 24 may first be pumped through the casing 16 string to fill the annulus 62 surrounding the first stage 52 of casing 16 while rotating the first and second stages 52 and 54 to improve the cementing process. After the first stage 52 of casing 16 is cemented, the rotating stage collar 58 may be actuated or triggered from the locked configuration into an unlocked configuration. In the unlocked configuration, the first and second stages 52 and 54 of the casing 16 string are rotationally independent from one another. As a result, the second stage 54 may be rotated as cement 24 is pumped into the annulus 62 surrounding the second stage 54 without rotating the first stage 52 of casing 16. Indeed, the rotating stage collar 58 may be actuated from the locked configuration to the unlocked configuration without lifting the casing 16 string from the surface. In this manner, the cement 24 surrounding the first stage 52 may be undisturbed after the first stage cementing process is complete, while enabling rotation of the second stage 54 casing during completion of the second stage cementing process.

While only certain features of the invention have been illustrated and described herein, many modifications and changes will occur to those skilled in the art. It is, therefore, to be understood that the appended claims are intended to cover all such modifications and changes as fall within the true spirit of the invention. 

1. A system, comprising: a rotating stage collar, comprising: an upper collar configured to couple to a first length of tubular; a lower collar configured to couple to a second length of tubular; and an inner sleeve disposed within the upper collar and the lower collar, wherein the upper collar and the lower collar are rotationally fixed to one another when the inner sleeve is in a first position within the upper collar and the lower collar, wherein the upper collar and the lower collar are rotationally independent of one another when the inner sleeve is in a second position within the upper collar and the lower collar, and wherein the second position is axially beneath the first position relative to a longitudinal axis of the rotating stage collar when the rotating stage collar is positioned within a wellbore.
 2. The system of claim 1, wherein inner sleeve comprises a plurality of locking dogs extending radially outward from the inner sleeve through respective guide slots of the upper collar, the lower collar comprises a plurality of locking slots, and the plurality of locking dogs extends into the plurality of locking slots and radially overlaps with the plurality of locking slots when the inner sleeve is in the first position.
 3. The system of claim 2, wherein the lower collar comprises a cavity disposed axially beneath the plurality of locking slots relative to the longitudinal axis of the rotating stage collar when the rotating stage collar is positioned within the wellbore, and the plurality of locking dogs is disposed within the cavity when the inner sleeve is in the second position.
 4. The system of claim 1, wherein the rotating stage collar comprises a load nut disposed radially about the upper collar and the lower collar, and the load nut is threaded to the lower collar.
 5. The system of claim 4, wherein the upper collar comprises a load shoulder, and the load shoulder is axially captured between an upper shoulder of the load nut and an axial end face of the lower collar.
 6. The system of claim 4, wherein the rotating stage collar comprises a first thrust bearing disposed axially between the load shoulder and the upper shoulder of the load nut and a second thrust bearing disposed axially between the load shoulder and the axial end face of the lower collar.
 7. The system of claim 1, wherein the inner sleeve is axially fixedly attached to the upper collar via a plurality of shear screws when the inner sleeve is in the first position.
 8. The system of claim 7, wherein the inner sleeve is rotationally fixed to the upper collar via a plurality of locking dogs extending through respective guide slots of the upper collar when the inner sleeve is in the second position.
 9. The system of claim 1, wherein the inner sleeve comprises a plug seat formed in an inner diameter of the inner sleeve.
 10. The system of claim 9, comprising a plug configured to land against the plug seat and occlude an inner passage of the rotating stage collar.
 11. The system of claim 1, wherein the upper collar comprise a plurality of cement ports formed in an outer surface of the upper collar, and the inner sleeve occludes the plurality of cement ports when the inner sleeve is in the first position.
 12. The system of claim 11, wherein the plurality of cement ports is open from an inner passage of the rotating stage collar to an outer surface of the upper collar when the inner sleeve is in the second position.
 13. A system, comprising: a first tubular configured to be secured within a wellbore; a second tubular configured to be secured within the wellbore; and a rotating stage collar, comprising: an upper collar coupled to the first tubular; a lower collar coupled to the second tubular; a load nut disposed radially about the upper collar and threaded to the lower collar; and an inner sleeve disposed within the upper collar and the lower collar, wherein the upper collar and the lower collar are rotationally fixed relative to one another when the inner sleeve is in a first position within the upper collar and the lower collar, and the upper collar and lower collar are rotationally independent of one another when the inner sleeve is in a second position within the upper collar and the lower collar, and wherein the second position is axially beneath the first position relative to a longitudinal axis of the rotating stage collar when the rotating stage collar is positioned within the wellbore.
 14. The system of claim 13, wherein the first tubular comprises a first length of casing, and the second tubular comprises a second length of casing.
 15. The system of claim 13, comprising a plug configured to land against a plug seat of the inner sleeve to occlude an inner passage of the rotating stage collar.
 16. The system of claim 13, wherein the lower collar comprises a plurality of slots formed in an inner diameter of the lower collar and a cavity formed in the inner diameter of the lower collar, wherein the cavity is axially beneath the plurality of slots relative to the longitudinal axis of the rotating stage collar when the rotating stage collar is positioned within the wellbore; and wherein the inner sleeve comprises a plurality of locking dogs extending radially outward from the inner sleeve, wherein the plurality of locking dogs is radially aligned with the plurality of slots relative to the longitudinal axis in the first position, and wherein the plurality of locking dogs is radially aligned with the cavity relative to the longitudinal axis in the second position.
 17. The system of claim 13, wherein the upper collar comprises a plurality of ports extending from an outer surface of the upper collar to an inner surface of the upper collar, wherein the inner sleeve occludes the plurality of ports when the inner sleeve is in the first position, and wherein the plurality of ports is open when the inner sleeve is in the second position.
 18. A method, comprising: coupling a lower collar of a rotating stage collar to a first stage of casing; coupling an upper collar of the rotating stage collar to a second stage of casing; positioning the first stage of casing, the rotating stage collar, and the second stage of casing into a wellbore; rotating the first stage of casing, the rotating stage collar, and the second stage of casing while completing a first stage cementing process; displacing an inner sleeve of the rotating stage collar axially downward within the upper collar and the lower collar to rotationally disengage the upper collar from the lower collar; and rotating the second stage of casing without rotating the first stage of casing while completing a second stage cementing process.
 19. The method of claim 18, wherein displacing the inner sleeve of the rotating stage collar axially downward within the upper collar and the lower collar comprises: launching a plug down the second stage of casing to the rotating stage collar; landing the plug against a plug seat of the inner sleeve; shearing pins coupling the inner sleeve to the upper collar; and displacing a plurality of locking dogs of the inner sleeve axially downward to disengage the plurality of locking dogs from a plurality of slots formed in the lower collar.
 20. The method of claim 18, wherein displacing the inner sleeve of the rotating stage collar axially downward within the upper collar and the lower collar comprises opening a plurality of cement ports formed in the upper collar, wherein each of the plurality of cement ports extends from an inner surface of the upper collar to an outer surface of the upper collar. 